Conventional seismic data processing methods are based on detecting primary reflections using a line (2D) or a grid (3D) of receivers placed on or near the surface of a geologic zone of interest. The position of each receiver is known relative to a source of seismic energy, which when triggered creates acoustic mechanical waves, which in turn activate electro-mechanical transducers that are an element of each receiver. Each mechanical wave can activate one or more transducers while outbound from its source, then again upon a first reflection from a subsurface interface or boundary (sometimes called an “event”), and then again upon one or more secondary or tertiary reflections. Electro-magnetic signals generated by the transducers are recorded or “gathered” (i.e. creating a seismogram to represent the primary reflected waves), then position corrected or “migrated”, and later “stacked” with sibling signals recorded by the same receiver during subsequent activations of the same source in order to reduce the influence of transient noise. Using any of a number of available algorithms that accept as data such signals resulting from primary reflections, gathers are processed to generate images that reveal substantially horizontal boundaries or interfaces at different depths, which images represent events or layers against which the mechanical waves were at different times reflected and through which those waves travel at different velocities that depend in part on the properties of the surface of those events and the composition of those layers.
It is understood that information respecting primary reflections arriving at different receivers at different times from sub-horizontal events can be coordinated and interpreted to accurately identify subsurface reflectors that are instead oriented somewhat vertically (known as sub-verticals) to within a limited range of angles (normally less than 60 degrees). For these mildly vertical reflectors such extrapolation from primary reflections has been developed to filter out complex double reflections and ignore their influence on resulting images as noise. However, for more steeply vertical reflectors such techniques extrapolating from primary reflections are insufficient to generate unambiguous images so as to reveal the existence, position, and orientation of such events to an acceptable level of certainty.
Where a vertically oriented reflector is sufficiently large or otherwise distinct (e.g. well known faults that are used as reference reflectors for testing and calibrating systems), conventional technologies can gather signals strong enough for experienced users to successfully extrapolate the required vertical information from horizontal information. However, when the steeply dipping reflector is a more subtle fault, even the most skilled users are exposed to a margin of error that is unacceptably large for the purpose of deciding where to spend millions of dollars drilling into a formation, which requires a high level of confidence that the deduced image is both genuine and located where calculated.
One example of such conventional seismic data processing methods is described in Ukraine Patent #42312, G01V1/100, G01V1/40, publ. 15 Oct. 2001 Bulletin #9, issued to Maramlevsky et al. (“312”) respecting a seismic reflection method for studying steeply dipping (i.e. sub-vertical) reflectors, whereby a linear group of sources is placed orthogonally to the plane of the exploration target, and the receivers are located both on the surface and in a borehole. The data is processed by multi-channel filtration to enhance primary waves that are reflected and dispersed from sub-vertical dipping and curvilinear boundaries. The seismic images of boundaries are generated based on the concurrent analysis of both the surface and the subsurface data, which determines spatial positioning and tests the validity of the constructed images. Disadvantageously, the method of 312 requires recordings from deep in a borehole, reducing its practical application, and processes only primary reflections.
Another example of conventional seismic data processing method is described in USSR Patent #894633, M. Kl. G01V1/100, publ. 30 Dec. 81 Bulletin #48, issued to Shalishov et al (“633”) respecting a seismic reflection method for steeply dipping reflectors, which is based on generation and recording of reflected waves along a linear profile of several sources that are located on the dip side of the steeply dipping surface. The interval between source and receiver points is selected to be no smaller than double the distance between the source point and the projection of the edge of the target surface onto the line of the source profile. Waves are recorded from the common point of double reflection—i.e. “duplex” waves, meaning those waves (commonly referred to as “formed under conditions of a spatial corner”) that have undergone double reflection—the first or primary reflection from the steeply dipping target surface and, the secondary reflection from any flat surface. The method of 633 assumes the recording of waves from points of common double reflection with certain delays, which assures in-phase summing, minimal distortion, and the maximum suppression of noise. Disadvantageously, the method of 633 requires special positioning of receivers and sources in relation to the dipping surface of the sub-vertical target, which leads to ambiguity unless there is prior data about the dip direction of the event. Further, the method of 633 provides an increased signal-to-noise ratio only for the duplex wave, without providing for a method of forming an image of the sub-vertical events (“SVE”).
The development of migration procedures in recent years has permitted increased accuracy in mapping areas having complex geology, including areas having salt domes. However, precise delineation of salt stocks, tracing of faults, and other problems connected with near-salt sediments, often still result in ambiguous solutions because sub-vertical reflecting boundaries have rugose surfaces. Waves reflected only once from such boundaries, tend not to reach the surface (at least within the observation geometry) and have been studied using “vertical seismic profiles” (VSP) according to which seismic images are created using a special migration transformation. However, the practical efficiency of such an approach is limited, because in the boreholes such reflections can only be recorded at depth intervals deeper than the target boundary. However, some waves can be reflected by sub-vertical faces of salt stocks and subsequently by sub-horizontal boundaries in adjacent sediments, permitting them to be recorded on the surface if they have enough energy to be identified against the background of other reflections. In Russia such waves are known as “duplex”, having undergone two reflections during propagation. Duplex waves can be formed not only under conditions of salt dome tectonics, but also at small-displacement faults, when the acoustic properties of the fault contrast significantly with those of the host rock. This commonly happens when the fault is a tectonic element of a hydrocarbon trap and, therefore, the epigenetic alterations associated with the deposit result in a significant acoustic contrast across the dislocation zone. Consequently, while it is difficult to use phase-shift analysis (due to the low resolving power of conventional seismic processing methods) duplex waves can be used to identify and trace faults with small displacements.
Typically, after “shooting” a new set of raw data—substantial work will be done to create the basic seismic data used for conventional processing of information relating to primary reflections. For example, if the soil within the observation surface (3D) or observation profile (2D) is uneven or composed of compressible material such as topsoil, then the raw data will typically be normalized or static corrections made, or filtered to remove the effects of surface waves. Such work as is used for pre-stack migration results in an output data set that is easier to use in future processing.
All such conventional processing requires a velocity model to define the propagation velocity of acoustic energy through the subject geologic medium (whether for a 3D cube or a 2D cross-section) at different depths. Sometimes the velocity model used is derived from actual well logs that directly identify what kind of medium is present at each of those different depths. Knowing or assuming a propagation velocity of acoustic energy through the subject geologic medium permits users to calculate the position over time of each point on a wave-front, which in turn permits the extrapolation of information regarding the position of any event from which that wave-front is believed to have been reflected. If the velocity model is not accurate, then position information respecting the base boundaries will be different when calculated based on primary reflections originating from different sources, which will cause the base boundary to “move” as the assumptions built-in to the velocity model are adjusted. These position errors can be used to allow an experienced user to instinctively adjust either the position or the model, to reduce the error as between different sets of assumptions. However, disadvantageously, for conventional processing of planes or cubes including sub-horizontal reflectors—only one side of each horizontal reflector is accessible from which to calculate its position such that errors in the velocity model result in errors in the position of the generated image of such horizontal reflectors, relative to their true position. It is therefore desirable to have means and a method to improve both a velocity model and the calculated position of the image of a reflector.
The prior art in the seismic data processing industry has concentrated on teaching variations of and refinements on the use of primary reflected energy, often treating multiple reflections as noise. However, even where duplex waves resulting from secondary or subsequent reflections is taken into account, the prior art relies on special configurations of the detection system. Accordingly it is desirable to have a method that uses information previously considered to be noise, and requires no special setup such that pre-existing recorded data may be reprocessed to obtain new information.
Conventional seismic acquisition and processing use primary reflected waves propagating from the surface source, then reflecting from some sub-surface event (e.g. an individual reflector, a boundary, or an interface between layers of different compositions), and then traveling back to the surface where they are observed. Disadvantageously, primary reflections from steeply dipping boundaries may reach the observation surface far outside the observation geometry or not reach it at all. Events that may be imaged using mainly primary reflections are commonly referred to as sub-horizontal boundaries, whereas steeply dipping or inclined boundaries that are difficult to identify using only primary reflections are referred to as sub-vertical boundaries or sub-vertical events (“SVE”). Waves returning to the surface from major sub-horizontal or “base” boundaries may be both reflected and refracted, which can be of practical significance since high-velocity layers (e.g. limestone) are commonly the strongest reflection boundaries on which pronounced refracted waves may be formed.
By way of definition, migration is an inversion operation during which seismic data elements are rearranged in order to plot images of reflectors at their true location, but includes the data processing and corrective adjustments necessary for the 2-D case to generate an image including the position of corrected faults. Modeling is the generation of a seismic environment based on artificial data. Imaging is used in the wider sense to include the data processing required to create an “image”. Vizualization is used in the narrow sense of creating output for viewing on a screen or printout. And, Geometric place of the points (“GPP”) means the position of points relating to a geometric construct. For example, a sphere is a GPP having the same distance from its center to each point on its surface. Each receiver in an observation geometry records (the amplitude of) seismic signals from a source as a function of time (t). The beginning of signal generation by a source corresponds to t=0. Seismic signals recorded by one receiver are known as a “trace” (amplitude as function of time). Traces normally are combined in a “gather”. Traces may be combined in different ways, for example, traces relating to one source represent Common Source Gather (“CSG”), whereas traces relating to one receiver recording from different sources are known as a Common Receiver Gather (“CRG”).